Apparatus and method for inflow control

ABSTRACT

A wellbore servicing apparatus comprising an inflow control assembly having an inflow flowbore and a stimulation assembly having a stimulation flowbore is disclosed. A method of servicing a wellbore comprising placing a stimulation assembly in the wellbore and placing at least one inflow control assembly in the wellbore, the at least one inflow control assembly comprising a selectively adjustable inflow sleeve, is also disclosed. A method of servicing a wellbore comprising opening a plurality of jetting nozzles in a production string located in a wellbore adjacent a formation, jetting a treatment fluid through the nozzles and perforating and/or fracturing the formation, at least partially closing the plurality of jetting nozzles, opening a plurality of inflow ports to allow fluid to flow from the formation into the production string, and filtering the fluid prior to the fluid entering the inflow ports is disclosed.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a fracturing fluid may be introduced into a portion of a subterranean formation penetrated by a wellbore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Stimulating or treating the wellbore in such ways increases hydrocarbon production from the well. The fracturing equipment may be included in a completion assembly used in the overall production process.

In some wells, it may be desirable to individually and selectively create multiple fractures along a wellbore at a distance apart from each other, creating multiple “pay zones.” The multiple fractures should have adequate conductivity, so that the greatest possible quantity of hydrocarbons in an oil and gas reservoir can be drained/produced into the wellbore. When stimulating a formation from a wellbore, or completing the wellbore, especially those wellbores that are highly deviated or horizontal, it may be advantageous to create multiple pay zones with a series of actuatable sleeve assemblies disposed in a downhole tubular. The actuatable sleeve assemblies are also referred to as sleeves or casing windows.

A stimulation sleeve may include a section of tubing having holes or apertures pre-formed in the tubing, and a sliding sleeve movable relative to the tubing section. The sliding sleeve also includes apertures alignable with the apertures in the tubing section. Upon actuation of the stimulation sleeve, such as by ball drop or other obturating member interference, the sliding sleeve moves and the sliding sleeve apertures are aligned with the tubing section apertures. This exposes the reservoir to the interior of the tubing string, and vice versa. The flow path created between the reservoir and the tubing string through the stimulation sleeve can be used for fracturing or production operations. The apertures in the tubing section may include jet forming nozzles to provide a fluid jet into the formation, causing tunnels and fractures therein.

Using multiple stimulation sleeves to create multiple formation zones may allow full wellbore access and increase hydrocarbon production; however, such operation may suffer from a variety of challenges depending on wellbore conditions such as an imbalanced inflow throughout a formation zone, production of water and gas, etc. Enhancement in methods and apparatuses to overcome these challenges can further improve hydrocarbon production. Thus, there is an ongoing need to develop new methods and apparatuses to enhance hydrocarbon production.

SUMMARY

The present invention, in at least one embodiment among others, relates to a wellbore servicing apparatus comprising at least one inflow control assembly having an inflow flowbore and at least one stimulation assembly having a stimulation flowbore, the stimulation flowbore being in fluid communication with the inflow flowbore.

The present invention, in at least one embodiment among others, further relates to a method of servicing a wellbore comprising placing at least one stimulation assembly in the wellbore, the at least one stimulation assembly comprising a selectively adjustable stimulation sleeve and a stimulation flowbore, and placing at least one inflow control assembly in the wellbore, the at least one inflow control assembly comprising a selectively adjustable inflow sleeve and an inflow flowbore.

The present invention, in at least one embodiment among others, further relates to a method of servicing a wellbore, comprising opening a plurality of jetting nozzles in a production string located in a wellbore adjacent a formation, jetting a treatment fluid through the nozzles and perforating and/or fracturing the formation, at least partially closing the plurality of jetting nozzles, opening a plurality of inflow ports to allow fluid to flow from the formation into the production string, and filtering the fluid prior to the fluid entering the inflow ports.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description:

FIG. 1 is a schematic, partial cross-sectional view of a wellbore completion apparatus in an operating environment;

FIG. 2 is a cross-sectional view of an inflow control assembly of the wellbore completion apparatus of FIG. 1;

FIG. 3 is a cross-sectional view of a stimulation assembly of the wellbore completion apparatus of FIG. 1;

FIG. 4 is a cross-sectional view of an alternative embodiment of an inflow control assembly;

FIG. 5 is an alternative embodiment of a wellbore completion apparatus;

FIG. 6 is another alternative embodiment of a wellbore completion apparatus; and

FIG. 7 is a further alternative embodiment of a wellbore completion apparatus.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed infra may be employed separately or in any suitable combination to produce desired results.

Unless otherwise specified, any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Reference to up or down will be made for purposes of description with “up”, “upper”, “upward” or “upstream” meaning toward the surface of the wellbore and with “down”, “lower”, “downward” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. The term “zone” or “pay zone” as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally and/or vertically spaced portions of the same formation. The term “seat” as used herein may be referred to as a ball seat, but it is understood that seat may also refer to any type of catching or stopping device for an obturating member or other member sent through a work string fluid passage that comes to rest against a restriction in the passage. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

Several wellbore servicing apparatus embodiments are disclosed herein. Each wellbore servicing apparatus may comprise multiple wellbore completion apparatuses disposed in a work string. Each wellbore completion apparatus comprises at least one stimulation assembly and at least one inflow control assembly, thereby allowing selective zone treatment (e.g., perforation and/or fracturing) and production, respectively. Optimization of hydrocarbon production and minimization of unwanted fluid production (such as water and gas) in completion operations may be achieved using a wellbore completion apparatus having at least one selective inflow control assembly and at least one selective stimulation assembly in each formation zone. Each inflow control assembly can be independently selectively actuated to control and/or restrict inflow at different formation zones at different times. Each stimulation assembly can also be independently selectively actuated to expose different formation zones to stimulation (e.g., flow of a treatment fluid, e.g., fracturing fluid, from an inner fluid passage of the work string) at different times. As discussed infra in greater detail, the different assemblies of a wellbore completion apparatus may be configured in the formation zone in any suitable combination.

Referring to FIG. 1, an embodiment of a wellbore servicing apparatus 100 is shown in an exemplary operating environment. While the wellbore servicing apparatus 100 is shown and described with specificity, various other wellbore servicing apparatus embodiments consistent with the teachings herein are described infra. As depicted, the operating environment comprises a drilling rig 106 that is positioned on the earth's surface 104 and extends over and around a wellbore 114 that penetrates a subterranean formation 102 for the purpose of recovering hydrocarbons. The wellbore 114 may be drilled into the subterranean formation 102 using any suitable drilling technique. The wellbore 114 may extend substantially vertically away from the earth's surface 104 over a vertical wellbore portion 116, or may deviate at any angle from the earth's surface 104 over a deviated or horizontal wellbore portion 118. In alternative operating environments, all or portions of the wellbore 114 may be vertical, deviated, horizontal, and/or curved.

At least a portion of the vertical wellbore portion 116 is lined with a casing 120 that is secured into position against the formation 102 in a conventional manner using cement 122. In alternative operating environments, the horizontal wellbore portion 118 may be cased and cemented and/or portions of the wellbore 114 may be uncased. In an alternative embodiment, the horizontal wellbore portion may remain uncemented, but further integrate the use of Swellpackers™ (commercially available from Halliburton Energy Services, Inc.) that are deployed to develop at least partially sealed compartments in the horizontal sections. The drilling rig 106 comprises a derrick 108 with a rig floor 110 through which a tubing or work string 112 extends downward from the drilling rig 106 into the wellbore 114. The work string 112 delivers the wellbore servicing apparatus 100 to a predetermined depth within the wellbore 114 to perform an operation such as perforating a casing and/or formation, expanding a fluid path therethrough, fracturing the formation 102, producing hydrocarbons from the formation 102, or other completion operation. The drilling rig 106 may be conventional and may comprise a motor driven winch and other associated equipment for extending the work string 112 into the wellbore 114 to position the wellbore servicing apparatus 100 at the desired depth.

While the exemplary operating environment depicted in FIG. 1 refers to a stationary drilling rig 106 for lowering and setting the wellbore servicing apparatus 100 within a land-based wellbore 114, one of ordinary skill in the art will readily appreciate that mobile workover rigs, wellbore servicing units (such as coiled tubing units), and the like may be used to lower the wellbore servicing apparatus 100 into the wellbore 114. It should be understood that the wellbore servicing apparatus 100 may alternatively be used in other operational environments, such as within an offshore wellbore operational environment.

The wellbore servicing apparatus 100 comprises an upper end having a liner hanger 124 (such as a Halliburton VersaFlex® liner hanger), a lower end 128, and a tubing section 126 extending therebetween. The lower end 128 has a float shoe 130 and a float collar 132 of a type known in the art connected therein, and tubing conveyed devices 134 connected therein. The tubing section 126 further comprises a plurality of packers 152 (such as Halliburton Swellpacker™ Isolation Systems) that function to isolate formation zones, thereby creating formation zones 2, 4, 6, 8, 10, and 12 that are isolated from each other along the tubing section 126. For example, the Swellpacker™ Isolation System is adapted to swell when exposed to hydrocarbons, water, gas, or combinations thereof. In alternative embodiments, any suitable packers may be used such as inflatable packers, squeeze packers, production packers, or combinations thereof.

The horizontal wellbore portion 118 and the tubing section 126 define an annulus 138 therebetween. The tubing section 126 comprises an interior wall 140 that defines a flow passage 142 therethrough. An inner string 144 is disposed in tubing section 126 and the inner string 144 extends therethrough so that an inner string lower end 146 extends into and is received by a polished bore receptacle 136. The inner string 144 may be used to carry cement 122 if the completion operation requires cement 122. Alternatively, cement 122 may not be utilized and the tubing section 126 may not comprise the inner string 144 so that the flow passage 142 is the main flowbore through the wellbore servicing apparatus 100.

By way of a non-limiting example, six wellbore completion apparatuses 190 are connected in-line with each other and housed in the tubing section 126. A single wellbore completion apparatus 190 is placed in each of the formation zones 2, 4, 6, 8, 10, and 12, and are thereby isolated from each other by the packers 152 as described infra. Each wellbore completion apparatus 190 comprises an inflow control assembly 148 placed adjacent a stimulation assembly 150. Thus, the inflow control assemblies 148 are disposed alternatingly along the length of the tubing section 126 with the stimulation assemblies 150. In other words, a stimulation assembly 150 is disposed adjacent an inflow control assembly 148 that is disposed adjacent another stimulation assembly 150 that is disposed adjacent another inflow control assembly 148, etc.

In an embodiment, the stimulation assemblies 150 are ball drop activated. In alternative embodiments, the stimulation assemblies may be mechanical shift activated, hydraulically activated, electrically activated, or combinations thereof to allow or prevent access to a formation zone (e.g., to open and/or close a window or sliding sleeve). In an alternative embodiment of a stimulation assembly, any of the mechanical shift activated, hydraulically activated, and electrically activated systems may be triggered or otherwise controlled using a pressure pulse system, such as the HalSonics™ system that is commercially available from Halliburton Energy Services, Inc. Examples of suitable stimulation assemblies 150 include, without limitation, Delta Stim® Sleeves which are also available from Halliburton Energy Services, Inc.

In an embodiment, activation of the inflow control assembly 148 is accomplished by ball drop. However, alternative embodiments of inflow control assemblies may include, without limitation, mechanical shift actuation, hydraulic actuation, electrical actuation, etc., to allow or prevent access to a formation zone (e.g., to open and/or close a window or sliding sleeve). An example of mechanical actuation includes a mechanical shift activation similar to the mechanical actuation of the mechanical shift activated Delta Stim® Sleeves. An example of hydraulic actuation includes a ball drop activation similar to the one on the ball drop activated Delta Stim® Sleeves. Further, in an alternative embodiment of an inflow control assembly, any of the mechanical shift activated, hydraulically activated, and electrically activated systems may be triggered or otherwise controlled using a pressure pulse system, such as the HalSonics™ system that is commercially available from Halliburton Energy Services, Inc. Generally, the inflow control assemblies differ from the stimulation assemblies in that the inflow control assemblies have additional structures that can restrict inflow of unwanted fluid such as gas and water and/or particles, which will be described infra.

Referring now to FIG. 2, a wellbore completion apparatus 190 comprising packers 152 on each end is shown. The wellbore completion apparatus 190 comprises the stimulation assembly 150 placed adjacent and above the inflow control assembly 148. The inflow control assembly 148 comprises an inflow housing 154 with an inflow sleeve 156 detachably connected therein. The inflow housing 154 comprises a plurality of inflow housing ports 178 defined therein. The inflow sleeve 156 has an inflow sleeve lower end 158. The inflow sleeve 156 further comprises a central inflow flowbore 157 that allows fluid communication between the inflow control assembly 148 and the flow passage 142 (shown in FIG. 1). After being detached from the inflow housing 154, the inflow sleeve 156 is slidable or movable in the inflow housing 154 as explained infra. The inflow housing 154 has an inflow housing upper end 160 and an inflow housing lower end 162, both of which are configured to be directly connected to or threaded into tubing section 126 (or to other stimulation assemblies 150 and/or inflow control assemblies 148) such that the inflow housing 154 makes up a part of the tubing section 126 shown in FIG. 1. Still referring to FIG. 2, the inflow sleeve 156 is initially connected to the inflow housing 154 with an inflow snap ring 164 that extends into an inflow groove 166 defined on an inflow housing inner surface 168 of the inflow housing 154. In addition, inflow shear pins (not shown) extend through the inflow housing 154 and into the inflow sleeve 156 to detachably connect the inflow sleeve 156 to the inflow housing 154. Inflow guide pins 170 are threaded or otherwise attached to the inflow sleeve 156 and are received in inflow axial grooves or inflow axial slots 172 of the inflow housing 154. The inflow guide pins 170 are slidable in the inflow axial slots 172 thereby preventing relative rotation between the inflow sleeve 156 and the inflow housing 154. The inflow sleeve 156 has a plurality of inflow sleeve ports 174 therethrough. An inflow annular gap 175 formed by a recess of the interior wall of the inflow housing 154 serves to provide a fluid path between the inflow sleeve ports 174 and the inflow housing ports 178 when the inflow sleeve ports 174 are at least partially radially aligned with the inflow annular gap 175. The inflow control assembly 148 further comprises a screen 176, one or more pressure altering devices 180, and a port cover 182.

The screen 176, disposed about a portion of the inflow housing 154 (e.g., adjacent inflow housing ports 178), is used to filter debris and may be constructed of wire wraps. However, in alternative embodiments, the screen may be made from any type of filter material such as mesh, sintered materials, etc. The pressure altering devices 180 are nozzles positioned adjacent to (e.g., screwed into) and/or within the inflow housing ports 178. The pressure altering devices 180 can restrict inward fluid flow through the inflow housing ports 178 during production of hydrocarbons thereby creating a pressure differential between the inflow flowbore 157 and the formation zones 2, 4, 6, 8, 10, and 12. The pressure altering device 180 can also delay early breakthrough of unwanted fluid (e.g., water, gas, etc.). In other alternative embodiments, the pressure altering devices may be tubes, pipes, or a combination of nozzles, wrapped tubing, tubes, baffles, channels, pipes, and/or any other structure suitable for altering pressure. The port cover 182 covers the inflow housing ports 178 and pressure altering devices 180, thus protecting the inflow housing ports 178 and pressure altering devices 180 from being clogged. The screen 176 may be disposed within or adjacent to a flow path created by the port cover 182 such that any fluid flow through the pressure altering devices 180 and/or inflow housing ports 178 must first pass through and be filtered by the screen 176.

Still referring to FIG. 2, the inflow sleeve ports 174 are radially misaligned (or longitudinally offset along the central lengthwise axis of the inflow control assembly 148) from the inflow annular gap 175 such that the inflow control assembly 148 is in a closed position where there is no access to the formation zones 2, 4, 6, 8, 10, and 12. In other words, in the closed position, there is no fluid path between the inflow flowbore 157 and the formation zones. The inflow sleeve 156 has an inflow seat ring 184 operably associated therewith and is connected therein at or near the inflow sleeve lower end 158. The inflow seat ring 184 has an inflow seat ring central opening 186 defining a seat ring diameter therethrough. The inflow seat ring 184 also has an inflow seat surface 188 for engaging an obturating member that may be dropped through the work string 112.

To move the inflow sleeve 156 from the closed position to an open position, an obturating member, such as a closing ball (not shown), may be dropped through the work string 112 so that it engages the inflow seat surface 188 on the inflow seat ring 184. Although the obturating member is typically a ball, other types of obturating members may be used such as plugs and darts that engage the inflow seat surface 188 and prevent flow therethrough. With closing ball in placed on the inflow seat ring 184 and blocking flow, pressure is increased to overcome the holding force applied by the inflow snap ring 164 and the shear pins (not shown), thereby moving the inflow sleeve 156 to an open position where a fluid path exists between the inflow sleeve ports 174 and the inflow housing ports 178 via the inflow annular gap 175 to allow passage of fluids between the inflow flowbore 157 and the formation zones 2, 4, 6, 8, 10, and 12.

Referring now to FIG. 3, the wellbore completion apparatus 190 is again shown, but with the stimulation assembly 150 shown in greater detail. The stimulation assembly 150 has components similar to the inflow control assembly 148 in FIG. 2 as described infra.

The stimulation assembly 150 comprises a stimulation housing 202 with a stimulation housing upper end 208 and a stimulation housing lower end 210, both of which are configured to be directly connected or threaded into tubing section 126 (or to other stimulation assemblies 150 and/or inflow control assemblies 148) in a manner similar to the inflow control assembly 148 in FIG. 2. The stimulation housing 202 has a stimulation sleeve 204 detachably connected therein with a stimulation sleeve lower end 206. The stimulation housing 202 has a plurality of stimulation housing ports 224 defined therein. The stimulation sleeve 204 has a central stimulation flowbore 205 that allows fluid communication between the stimulation assembly 150 and the flow passage 142 (shown in FIG. 1).

Similar to the inflow control assembly 148 in FIG. 2, the stimulation sleeve 204 is initially connected to the stimulation housing 202 with a stimulation snap ring 212 that extends into a stimulation groove 214 defined on a stimulation housing inner surface 216 of the stimulation housing 202. In addition, stimulation shear pins (not shown) extend through the stimulation housing 202 and into the stimulation sleeve 204 to detachably connect the stimulation sleeve 204 to the stimulation housing 202. Stimulation guide pins 218 are threaded or otherwise attached to the stimulation sleeve 204 and are received in stimulation axial grooves or stimulation axial slots 220 of the stimulation housing 202. The stimulation guide pins 218 are slidable in the stimulation axial slots 220 thereby preventing relative rotation between the stimulation sleeve 204 and the stimulation housing 202. The stimulation sleeve 204 has a plurality of stimulation sleeve ports 222 therethrough. A stimulation annular gap 223 formed by a recess of the interior wall of the stimulation housing 202 serves to provide a fluid path between the stimulation sleeve ports 222 and the stimulation housing ports 224 when the stimulation sleeve ports 222 are at least partially radially aligned with the stimulation annular gap 223. In alternative embodiments of a stimulation assembly, the housing ports may be fitted with a fluid jet forming nozzle suitable for perforating and/or fracturing a formation zone as described infra.

The stimulation sleeve ports 222 are radially aligned with the stimulation annular gap 223 such that the stimulation assembly 150 is in an open position where there is access to the formation zones 2, 4, 6, 8, 10, and 12. In other words, in the open position, there is a fluid path between the stimulation flowbore 205 and the formation zones via the stimulation annular gap 223. The stimulation sleeve 204 has a stimulation seat ring 226 operably associated therewith and is connected therein at or near the stimulation sleeve lower end 206. The stimulation seat ring 226 has a stimulation seat ring central opening 228 defining a seat ring diameter therethrough. The stimulation seat ring 226 also has a stimulation seat surface 230 for engaging an obturating member 232 (shown as a ball) that is dropped through the stimulation flowbore 205 to actuate (e.g., open) the stimulation sleeve 204 by aligning the stimulation sleeve ports 222 and the stimulation housing ports 224.

In operation, a plurality of wellbore completion apparatuses 190 may be used in servicing the wellbore 114, for example, in a wellbore completion service. Generally, servicing a wellbore 114 is carried out starting from a formation zone in the furthest or lowermost end of the surface (i.e., toe) and sequentially backwards toward the closest or uppermost end of the surface (i.e., heel). The wellbore servicing begins by disposing a liner hanger 124 comprising a float shoe 130, a float collar 132, and a tubing section 126 comprising a plurality of wellbore completion apparatuses 190 separated from each other by a plurality of packers 152. The float shoe 130 and float collar 132 are disposed near the toe. The wellbore completion apparatuses 190 are positioned adjacent a plurality of formation zones 2, 4, 6, 8, 10, and 12 to be treated so that one wellbore completion apparatus 190 is placed adjacent each formation zone. The orientation of the wellbore completion apparatuses 190 may be horizontal, deviated, vertical, or angled, and can be selected based on the wellbore conditions. As previously explained, each wellbore completion apparatus 190 comprises at least one inflow control assembly 148 and at least one stimulation assembly 150. Next, a hydrocarbon fluid is disposed through the float shoe 130 to activate or swell the packers 152. If desired, cementing of the wellbore 114 is performed using cement 122. At this point, both the stimulation assemblies 150 and the inflow control assemblies 148 are closed, where the inflow sleeve ports 174 are radially misaligned from the inflow annular gaps 175 of the inflow assemblies 148, and the stimulation sleeve ports 222 are radially misaligned from the stimulation annular gaps 223 of the stimulation assemblies 150.

Once the packers 152 are activated or swelled, the first formation zone 12 (typically the lowermost zone near the toe) is exposed by aligning (i.e., opening) the stimulation sleeve ports 222 with the stimulation annular gap 223 of the first stimulation assembly 150 that is associated with the first formation zone 12. The aligning is carried out by dropping a first obturating member 232 (e.g., ball). In alternative embodiments, the aligning may be carried out by hydraulically applying pressure, or by mechanically or electrically shifting the stimulation sleeve 204 to move the stimulation sleeve ports 222. The aligning is carried out until stimulation sleeve ports 222 are completely aligned with the stimulation annular gap 223 to a fully opened position. In alternative embodiments, the aligning may be carried out until the stimulation sleeve ports 222 are partially aligned with the stimulation annular gap 223 to a partially opened position.

A wellbore servicing fluid (such as a fracturing fluid) may be pumped down the wellbore 114 at sufficient pressure to perforate and/or fracture the first formation zone 12. The wellbore servicing fluid may be pumped through the stimulation housing ports 224 at a velocity sufficient to form perforation tunnels and/or fractures within the first formation zone 12. A sufficient volume of fracturing fluid may be pumped through the open ports to expand and/or propagate the fractures into the formation.

Next, the second formation zone 10 may be exposed by any suitable method described infra, for example, by dropping another obturating member or mechanically shifting the stimulation sleeve 204 to align the stimulation sleeve ports 222 with the stimulation annular gap 223 of the stimulation assembly 150 associated with the second formation zone 10. The wellbore servicing fluid is again pumped down the wellbore 114 at sufficient pressure to form perforation tunnels and/or fracture the second formation zone 10. The procedure is repeated selectively and/or sequentially to service any selected and/or all formation zones 2, 4, 6, 8, 10, and 12. During fracturing, the inflow sleeve ports 174 of the inflow control assemblies 148 are at least partially misaligned (and preferably fully misaligned) from the inflow annular gaps 175 and at least partially (and preferably fully) closed to reduce the fluid path between the inflow flowbores 157 and the formation zones 2, 4, 6, 8, 10, and 12. In some operations, the inflow control assemblies 148 may be completely closed, eliminating a fluid flow path between the flowbores 157 and formation zones. If obturating members are used, they can be returned to the earth's surface 104, for example, by flowing back with a hydraulic fluid or retrieval with a fishing tool, or the obturating members may be otherwise removed for example by drilling out.

Once the selected formation zones are perforated and/or fractured, production fluid (e.g., hydrocarbons) can now flow through flow paths in the formation, through the stimulation housing ports 224 and the stimulation sleeve ports 222 of the stimulation assemblies 150, and into the stimulation flowbore 205 provided that such flow paths remain at least partially open. Alternatively, these flow paths may be partially or completely closed and the production of fluid from the formation controlled as follows.

Since sometimes the pressure of the various formation zones 2, 4, 6, 8, 10, and 12 can be unequal and imbalanced, which creates imbalanced inflow and often allows early breakthrough of non-desirable fluid, etc., the inflow control assemblies 148 are used to alter the pressure of fluid flowing into the inflow flowbores 157. To accomplish this, the stimulation assemblies 150 are next at least partially closed by moving (i.e., misaligning) the stimulation sleeve ports 222 away from the stimulation annular gaps 223. The stimulation sleeves 204 can be moved using any suitable tools or methods known in the art with the aid of this disclosure, for example, using a fishing tool on a wireline.

Next, to allow flow of fluid from the formation zones 2, 4, 6, 8, 10, and 12 into the inflow flowbore 157 with altered pressure, the inflow control assemblies 148 are at least partially (and preferably fully) opened. Similarly, the opening may be carried out by moving the inflow sleeves 156 by mechanically, hydraulically, or electrically shifting the inflow sleeves 156 until inflow ports 174 are at least partially aligned (i.e., partially opened) or are fully aligned (i.e., opened) with the inflow annular gaps 175. Production fluid is filtered through the screen 176 on the inflow control assemblies 148, and proceeds to flow through at least one pressure altering device 180 (e.g., nozzles, wrapped tubing, tubes, baffles, channels, pipes, and/or any other structure suitable for altering pressure), thereby altering (in this embodiment, lowering) the pressure of the flow of production fluids from the formation into the inflow flowbore 157. In other words, passing the wellbore servicing fluid through a pressure altering device 180 of the inflow control assembly 148 creates a pressure differential between the wellbore 114 and the inflow flowbore 157.

The number of zones, the order in which the inflow control assemblies and the stimulation assemblies are used (e.g., partially and/or fully opened and/or closed), the wellbore completion apparatuses, the stimulation assemblies, the inflow control assemblies, etc. shown herein may be used in any suitable combination and the configurations shown herein are not intended to be limiting and are shown only for exemplary purposes. Any desired number of formation zones may be treated or produced in any order.

Referring now to FIG. 4, an alternative embodiment of an inflow control assembly 300 is shown. The inflow control assembly 300 has a casing window configuration that operates to enable selective access to a formation zone. An associated (but not shown) alternative embodiment of a stimulation assembly may comprise a casing window configuration similar to the inflow control assembly 300, but the associated stimulation assembly would not comprise any pressure altering components and optionally no port cover 312.

The inflow control assembly 300 comprises an inflow cylindrical outer casing 302 that receives an inflow movable sleeve member 304. The inflow control assembly 300 also has a central inflow flowbore 305 that allow fluid communication between the inflow control assembly 300 and a flow passage of an associated work string. The inflow cylindrical outer casing 302 comprises one or more inflow outer casing apertures 306 to allow access for a fluid from the interior of the inflow cylindrical outer casing 302 into a formation zone 308. The inflow outer casing apertures 306 are coupled to a screen 316, a port cover 312, and pressure altering devices (e.g., pressure altering nozzles 310 and/or pressure altering pipes or tubes 314). The functions of the screen 316, the port cover 312, and the pressure altering devices (e.g., pressure altering nozzles 310 and/or pressure altering pipes or tubes 314) have been described supra. The pressure altering nozzles 310 are inserted into the inflow outer casing apertures 306 while the pressure altering pipes or tubes 314 are placed adjacent the screen 316 and inside the port cover 312. In alternative embodiments, pressure altering nozzles may be placed adjacent the outer casing apertures of the inflow control assembly, similar to the placement of the pressure altering device 180 of FIG. 2. The pressure altering nozzles 310 are isolated from the inflow annulus 318 (formed between the inflow cylindrical outer casing 302 and the inflow movable sleeve member 304) by inflow coupling seals or inflow fluid flow barriers 320 to the inflow cylindrical outer casing 302. An inflow annular gap 307 formed by a recess in the outer wall of the inflow movable sleeve member 304 serves to provide a fluid path between the inflow movable sleeve member apertures 322 and the inflow outer casing apertures 306 when the inflow outer casing apertures 306 are at least partially radially aligned with the inflow annular gap 307.

The inflow movable sleeve member apertures 322 can be selectively aligned with the inflow as annular gap 307 to allow passage of fluid from the formation zone 308 into the inflow flowbore 305 through the screen 316, the pressure altering pipes or tubes 314, inflow outer casing apertures 306 having pressure altering nozzles 310, and the inflow movable sleeve member apertures 322 via the inflow annular gap 307. The inflow movable sleeve member 304 can be shifted axially, rotatably, or by a combination thereof (to open and/or close) thereby selectively controlling flow of a fluid from the formation zone 308 into the inflow flowbore 305. The inflow movable sleeve member 304 may be shifted via any suitable mechanism such as mechanical shift actuation, hydraulic actuation, electric actuation, etc.

The wellbore completion apparatus comprising at least one inflow control assembly and at least one stimulation assembly may be used in a variety of combinations. The number of inflow control assemblies and the stimulation assemblies in each wellbore completion apparatus can be selected based on the conditions of the wellbore and/or any other suitable determining factor. For example, in a single wellbore completion apparatus, the number of inflow control assemblies may be 2, 3, 4, 5, or more, and the number of stimulation assemblies may be 2, 3, 4, 5, or more.

FIG. 5 is an exemplary combination of an inflow control assembly and a stimulation assembly in a wellbore completion apparatus 502. The wellbore completion apparatus 502 comprises an inflow control assembly 506 adjacent and above a stimulation assembly 508 with packers 504 and 510 on each end of the wellbore completion apparatus 502.

FIG. 6 shows a wellbore completion apparatus 512 that comprises an inflow control assembly 516 adjacent and above a stimulation assembly 518 that is adjacent and above another inflow control assembly 520 with packers 514 and 522 on each end of the wellbore completion apparatus 512.

FIG. 7 shows a wellbore completion apparatus 524 that comprises a stimulation assembly 528 adjacent and above an inflow control assembly 530 that is adjacent and above another stimulation assembly 532 that is adjacent and above another inflow control assembly 534 with packers 526 and 536 on each end of the wellbore completion apparatus 524.

While embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R_(L), and an upper limit, R_(U), is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R_(L)+k*(R_(U)−R_(L)), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference in the Description of Related Art is not an admission that it is prior art to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein. 

1. A wellbore servicing apparatus, comprising: at least one inflow control assembly having an inflow flowbore; and at least one stimulation assembly having a stimulation flowbore, the stimulation flowbore being in fluid communication with the inflow flowbore.
 2. The wellbore servicing apparatus according to claim 1, the at least one inflow control assembly comprises: an inflow housing having at least one inflow housing port; and an inflow sleeve having at least one inflow sleeve port, the inflow sleeve being movable with respect to the inflow housing to selectively provide a fluid flow path between the at least one inflow housing port and the at least one inflow sleeve port.
 3. The wellbore servicing apparatus according to claim 2, the at least one inflow control assembly further comprises: at least one pressure altering device.
 4. The wellbore servicing apparatus according to claim 3, wherein the at least one pressure altering device is selected from the group consisting of nozzles, wrapped tubing, tubes, baffles, channels, pipes, and any combination thereof.
 5. The wellbore servicing apparatus according to claim 3, the at least one inflow control assembly further comprises: a port cover at least partially covering the at least one inflow housing port.
 6. The wellbore servicing apparatus according to claim 3, the at least one inflow control assembly further comprising: a screen operably associated with the at least one pressure altering device.
 7. The wellbore servicing apparatus according to claim 6, wherein the screen is constructed of one of the group comprising wire wraps, mesh, sintered material, and any combination thereof.
 8. The wellbore servicing apparatus according to claim 6, the at least one inflow control assembly further comprising: a port cover at least partially covering the at least one inflow housing port.
 9. The wellbore servicing apparatus according to claim 3, wherein the inflow sleeve is moved by one of the group consisting of ball drop actuation, mechanical shifting actuation, mechanical actuation, hydraulic actuation, electrical actuation, and any combination thereof.
 10. The wellbore servicing apparatus according to claim 1, the stimulation assembly further comprising: a stimulation housing having at least one stimulation housing port; and a stimulation sleeve having at least one stimulation sleeve port, the stimulation sleeve being movable with respect to the stimulation housing to selectively provide a fluid flow path between the at least one stimulation housing port and the at least one stimulation sleeve port.
 11. The wellbore servicing apparatus according to claim 1, further comprising: a plurality of packers operably associated with the at least one inflow control assembly and the at least one stimulation assembly so that the at least one inflow control assembly and the at least one stimulation assembly are isolated within a formation zone.
 12. The wellbore servicing apparatus according to claim 11, wherein the packers are selected from the group consisting of swellable packers, inflatable packers, squeeze packers, production packers, and any combination thereof.
 13. A method of servicing a wellbore, comprising: placing at least one stimulation assembly in the wellbore, the at least one stimulation assembly comprising a selectively adjustable stimulation sleeve and a stimulation flowbore; placing at least one inflow control assembly in the wellbore, the at least one inflow control assembly comprising a selectively adjustable inflow sleeve and an inflow flowbore.
 14. The method according to claim 13, further comprising: transferring a wellbore servicing fluid from the stimulation flowbore to the wellbore while the at least one stimulation sleeve is at least partially open and provides a fluid path between the stimulation flowbore and the wellbore and while the at least one inflow sleeve is at least partially closed to at least partially reduce a fluid path between the inflow flowbore and the wellbore.
 15. The method according to claim 14, wherein the inflow sleeve is fully closed to eliminate a fluid path between the inflow flowbore and the wellbore during transferring of the wellbore servicing fluid from the stimulation flowbore to the wellbore.
 16. The method according to claim 14, wherein the stimulation sleeve is fully open to maximize a fluid path between the stimulation flowbore and the wellbore during transferring of the wellbore servicing fluid from the stimulation flowbore to the wellbore.
 17. The method according to claim 14, further comprising: after the wellbore servicing fluid has been transferred from the stimulation flowbore to the wellbore, at least partially closing the stimulation sleeve to reduce the fluid path between the stimulation flowbore and the wellbore and at least partially opening the inflow sleeve to increase the fluid path between the inflow flowbore and the wellbore.
 18. The method according to claim 14, wherein the wellbore servicing fluid is a fracturing fluid.
 19. The method according to claim 14, further comprising: passing the wellbore servicing fluid through a pressure altering device of the inflow control assembly, thereby creating a pressure differential between the wellbore and the inflow flowbore.
 20. The method according to claim 19, wherein the at least one stimulation assembly and the at least one inflow control assembly are isolated within a portion of the wellbore associated with a formation zone so that transferring the wellbore servicing fluid from the stimulation flowbore to the wellbore occurs within the formation zone and so that the pressure differential between the wellbore and the inflow flowbore is associated with the formation zone.
 21. The method according to claim 13, further comprising: selectively adjusting the stimulation sleeve to change a fluid path between the stimulation flowbore and the wellbore, thereby adjusting a flow of treatment fluid flow from the stimulation flowbore into the wellbore.
 22. The method according to claim 13, further comprising: selectively adjusting the stimulation sleeve to change a fluid path between the stimulation flowbore and the wellbore, thereby adjusting a flow of hydrocarbon fluid into the stimulation flowbore from the wellbore.
 23. The method according to claim 13, further comprising: selectively adjusting the inflow sleeve to change a fluid path between the inflow flowbore and the wellbore, thereby adjusting a pressure differential between the wellbore and the inflow flowbore.
 24. A method of servicing a wellbore, comprising: opening a plurality of jetting nozzles in a production string located in a wellbore adjacent a formation; jetting a treatment fluid through the nozzles and perforating and/or fracturing the formation; at least partially closing the plurality of jetting nozzles; opening a plurality of inflow ports to allow fluid to flow from the formation into the production string; and filtering the fluid prior to the fluid entering the inflow ports.
 25. The method of claim 24 further comprising decreasing the fluid pressure when flowing the fluid from the formation into the production string.
 26. The method of claim 24 further comprising isolating the jetting nozzles and the inflow ports from upper and lower portions of the wellbore prior to their opening. 